Flowable devices and methods of self-orienting the devices in a wellbore

ABSTRACT

A wellbore flowable device comprises an orientor, wherein the orientor causes the flowable device to be oriented within the wellbore such that the flowable device has a higher pressure differential rating than a similar flowable device without the orientor. A method of orienting the wellbore flowable device comprises: introducing the wellbore flowable device comprising the orientor into the wellbore; and allowing the flowable device to orient itself within the wellbore in a preselected orientation.

TECHNICAL FIELD

A flowable device and methods of self-orienting the flowable device are provided. The flowable device includes an orientor. The orientor orients the flowable device as it travels through the wellbore such that the flowable device is situated in a preselected orientation in the wellbore. The flowable device can have a higher pressure differential rating than a similar flowable device without the orientor. According to an embodiment, the flowable device is used in an oil or gas well operation.

SUMMARY

According to an embodiment, a wellbore flowable device comprises: an orientor, wherein the orientor causes the flowable device to be oriented within the wellbore such that the flowable device has a higher pressure differential rating that a similar flowable device without the orientor.

According to another embodiment, a method of orienting a flowable device in a wellbore comprises: introducing the flowable device into the wellbore, wherein the flowable device comprises: a body; and an orientor, wherein the orientor causes the flowable device to be oriented within the wellbore such that the flowable device has a higher pressure differential rating than a similar flowable device without the orientor.

According to another embodiment, a method of orienting a flowable device in a wellbore comprises: introducing the flowable device into the wellbore, wherein the flowable device comprises: an orientor; and a body, wherein the body comprises a plurality of layers, wherein each of the layers comprises one or more materials, and wherein after introduction, the orientor causes the flowable device to be oriented in a preselected orientation within the wellbore.

According to yet another embodiment, a method of orienting a flowable device in a wellbore comprises: introducing the flowable device into the wellbore, wherein the flowable device comprises: a body; an orientor; and a communication device, wherein the communication device is operatively coupled to a transmitter and a receiver, wherein the orientor causes the flowable device to be oriented in a preselected orientation within the wellbore, and when the flowable device is in the preselected orientation, a more efficient coupling exists between the transmitter and the receiver via the communication device compared to a similar flowable device without the orientor.

BRIEF DESCRIPTION OF THE FIGURES

The features and advantages of certain embodiments will be more readily appreciated when considered in conjunction with the accompanying figures. The figures are not to be construed as limiting any of the preferred embodiments.

FIG. 1 depicts a well system containing more than one flowable device.

FIGS. 2A-2C depict a flowable device, wherein the device is an isolation device.

FIG. 3 depicts a flowable device according to another embodiment.

FIG. 4 depicts the flowable device with a magnetic flux field.

FIGS. 5A-5C depict the flowable device of FIG. 4 according to certain embodiments.

FIGS. 6A-6B depict the flowable device containing a flexible member as the orientor.

DETAILED DESCRIPTION

As used herein, the words “comprise,” “have,” “include,” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps.

As used herein, a “fluid” is a substance having a continuous phase that tends to flow and to conform to the outline of its container when the substance is tested at a temperature of 71° F. (22° C.) and a pressure of one atmosphere “atm” (0.1 megapascals “MPa”). A fluid can be a liquid or gas. As used herein, a “flowable device” means an apparatus that is capable of flowing in or through a fluid in a wellbore.

Oil and gas hydrocarbons are naturally occurring in some subterranean formations. In the oil and gas industry, a subterranean formation containing oil, gas, or water is referred to as a reservoir. A reservoir may be located under land or off shore. Reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs). In order to produce oil or gas, a wellbore is drilled into a reservoir or adjacent to a reservoir. The oil, gas, or water produced from the wellbore is called a reservoir fluid.

A well can include, without limitation, an oil, gas, or water production well, an injection well, or a geothermal well. As used herein, a “well” includes at least one wellbore. The wellbore is drilled into a subterranean formation. The subterranean formation can be a part of a reservoir or adjacent to a reservoir. A wellbore can include vertical, inclined, and horizontal portions, and it can be straight, curved, or branched. As used herein, the term “wellbore” includes any cased, and any uncased, open-hole portion of the wellbore. A near-wellbore region is the subterranean material and rock of the subterranean formation surrounding the wellbore. As used herein, a “well” also includes the near-wellbore region. The near-wellbore region is generally considered the region within approximately 100 feet radially of the wellbore. As used herein, “into a well” means and includes into any portion of the well, including into the wellbore or into the near-wellbore region via the wellbore.

A portion of a wellbore may be an open hole or cased hole. In an open-hole wellbore portion, a tubing string may be placed into the wellbore. The tubing string allows fluids to be introduced into or flowed from a remote portion of the wellbore. In a cased-hole wellbore portion, a casing is placed into the wellbore that can also contain a tubing string. A wellbore can contain an annulus. Examples of an annulus include, but are not limited to: the space between the wellbore and the outside of a tubing string in an open-hole wellbore; the space between the wellbore and the outside of a casing in a cased-hole wellbore; and the space between the inside of a casing and the outside of a tubing string in a cased-hole wellbore.

It is not uncommon for a wellbore to extend several hundreds of feet or several thousands of feet into a subterranean formation. The subterranean formation can have different zones. A zone is an interval of rock differentiated from surrounding rocks on the basis of its fossil content or other features, such as faults or fractures. For example, one zone can have a higher permeability compared to another zone. It is often desirable to treat one or more locations within multiples zones of a formation. One or more zones of the formation can be isolated within the wellbore via the use of an isolation device.

An isolation device is an example of a flowable device. An isolation device can be used for zonal isolation and functions to block fluid flow within a tubular, such as a tubing string, or within an annulus. The blockage of fluid flow prevents the fluid from flowing across the isolation device in any direction and isolate the zone of interest. As used herein, the relative term “downstream” means at a location further away from a wellhead. In this manner, treatment techniques can be performed within the zone of interest. Common isolation devices include, but are not limited to, a ball and seat. It is to be understood that reference to a “ball” is not meant to limit the geometric shape of the ball to spherical, but rather is meant to include any device that is capable of engaging with a seat. A “ball” can be spherical in shape, but can also be a dart, a bar, or any other shape. Zonal isolation can be accomplished, for example, via a ball and seat by dropping the ball from the wellhead onto the seat that is located within the wellbore. The ball engages with the seat, and the seal created by this engagement prevents fluid communication into other zones downstream of the ball and seat. In order to treat more than one zone using a ball and seat, the wellbore can contain more than one ball seat. For example, a seat can be located within each zone. Generally, the inner diameter (I.D.) of the ball seats can be different for each zone. For example, the I.D. of the ball seats can sequentially decrease at each zone, moving from the wellhead to the bottom of the well. In this manner, a smaller ball is first dropped into a first zone that is the farthest downstream; that zone is treated; a slightly larger ball is then dropped into another zone that is located upstream of the first zone; that zone is then treated; and the process continues in this fashion—moving upstream along the wellbore—until all the desired zones have been treated. As used herein, the relative term “upstream” means at a location closer to the wellhead.

Another example of a flowable device is a device containing a communication device. The communication device can include an antenna that is capable of relaying a signal from a transmitter to a receiver. Communication devices are used in a variety of oil and gas applications including, but not limited to, obtaining information about wellbore fluids and conditions and controlling downhole tools.

Flowable devices made of metal have been typically used in some oil or gas operations. However, metallic flowable devices have several disadvantages including, their cost and high density. Consequently, flowable devices made from composite materials or plastics have been increasingly adopted in scenarios where expensive and complex permanent completion equipment is not required. Composite flowable devices have several advantages over metal containing devices. For example, composite devices can have favorable drillability characteristics (e.g., they can be easily drillable, or more easily drilled into compared to solid metal flowable devices). Composite flowable devices can also have a lower density compared to metallic flowable devices. After the well has been produced, it is often desirable to flow the flowable devices back up the wellbore to the wellhead to allow for better production. While this may be difficult with heavy metal flowable devices, composite flowable devices can be easily carried back to the wellhead since their density is less than metal devices and often less than the produced fluid. Moreover, it is easier to flow the device back to the wellhead due to the favorable drillability. Composite flowable devices can also possess increased rigidity and strength. Composite flowable devices can possess low warping tendency. Composite flowable devices exhibit a low coefficient of expansion and therefore, may be relatively stable when exposed to high downhole temperatures. Composite flowable devices can be easier and less expensive to manufacture. Due to these advantages, the use of flowable devices made from composite materials is becoming increasingly common in oilfield operations.

A composite flowable device typically comprises concentric laminate layers. These layers may be made of fibers that are held together by epoxy resins, carbon composites, graphite composite, woven fibers, and other lightweight materials. However, due to the presence of these concentric layers, the strength of the flowable device may not be isotropic (i.e., uniform in all directions). This anisotropic strength causes the flowable device to mechanically fail when it lands in a less than optimal orientation in the wellbore.

Flowable devices, such as, isolation devices, must maintain their strength and shape when introduced within the wellbore in order to function properly. For example, the flowable device must be capable of withstanding a specific pressure differential within the wellbore when functioning as an isolation device. As used herein, the term “withstanding” means that the substance does not crack, break, or collapse. The pressure differential can be the difference between the bottomhole pressure of the subterranean formation and the pressure in an area above or below the isolation device. Formation pressures can range from about 1,000 to about 30,000 pounds force per square inch (psi) (about 6.9 to about 206.8 megapascals “MPa”). The pressure differential can also be created during oil or gas operations. For example, a fluid, when introduced into the wellbore upstream or downstream of the flowable device, can create a higher pressure above or below, respectively, of the flowable device. Pressure differentials can range from about 100 to over 10,000 psi (about 0.7 to over 68.9 MPa).

Flowable devices can be rated according to their ability to withstand specific pressure differentials. A higher pressure differential rating can be indicative of an isolation device that is stronger and can substantially maintain its shape in the wellbore when compared to a similar flowable device with a lower pressure differential rating. It has been observed that the orientation of the flowable device after the device reaches the desired portion of the wellbore (e.g., after engagement with a seat), can affect the strength of flowable device and, consequently, its pressure differential rating.

Some of the drawbacks with the current practice of rating flowable devices include: difficulty in predicting the orientation of the flowable device within the wellbore and a lack of consistency to the ratings applied to similar flowable devices by different companies. The strength of a flowable device can be unpredictable because of the inability to ensure that the flowable device lands in a particular orientation once introduced into the wellbore. Ratings applied to flowable devices are also inconsistent. For instance, some companies may conservatively assign a lower pressure differential rating to a flowable device assuming an orientation that is sub-optimal. Other companies may assign a higher pressure differential rating to a similar device because they may be willing to assume that the device will land in an optimal orientation. Accordingly, there is no uniformity in the pressure differential ratings applied to even devices having substantially the same shape/size and constructed from the same material or materials.

When a flowable device is dropped or pumped within the wellbore, its orientation or alignment with respect to the wellbore can change. The change in orientation can be due to, for example, physical contact between the inner diameter of the tubing string and the surface of the device. This change in orientation can result in the inability of the device to withstand a higher pressure differential or for a communication device to be ineffectively aligned with a transmitter and receiver. There exists a need to optimally orient a flowable device after it is introduced into a wellbore.

A novel method of orienting a flowable device in a wellbore comprises providing the flowable device with an orientor such that the flowable device can autonomously, that is, without any external intervention, self-orient itself in the wellbore. As used herein, the term “orientor” encompasses one or more objects or devices that can cause the flowable device to be oriented in a preselected orientation after the flowable device has been introduced into the wellbore. The preselected orientation can be based on predetermined information on one or more of the following: the size, shape, and/or material of the flowable device; characteristics of the wellbore or wellbore components (such as the tubing string) in which it is introduced; and the physical and chemical composition of fluids in the wellbore. Since the flowable device can orient itself in the wellbore, costs associated with manufacturing the device can be decreased. For example, the flowable device can be manufactured from novel materials, lower cost composites or a mixture of composites, and metals that exhibit desired physical properties. Additionally, the flowable device can be manufactured from a material that can facilitate degradation/dissolution downhole. Furthermore, novel designs can be incorporated into the manufacturing process of the device. Other measures can also be taken to improve the strength of the flowable device.

In addition to its impact on the strength of a flowable device, a flowable device that can self-orient itself as it travels through the wellbore allows for improved wireless communication between the device and other flowable devices and downhole and/or surface tools. For example, an antenna can be attached to or placed inside the flowable device to transmit and/or receive information from other flowable devices or wellbore tools. Since the flowable device orients itself in a preselected orientation, the orientation of the antenna can be adjusted to facilitate optimal communication.

According to an embodiment, a wellbore flowable device comprises: an orientor, wherein the orientor causes the flowable device to be oriented within the wellbore such that the flowable device has a higher pressure differential rating that a similar flowable device without the orientor.

According to another embodiment, a method of orienting a flowable device in a wellbore comprises: introducing the flowable device into the wellbore, wherein the flowable device comprises: a body; and an orientor, wherein the orientor causes the flowable device to be oriented within the wellbore such that the flowable device has a higher pressure differential rating than a similar flowable device without the orientor.

According to another embodiment, a method of orienting a flowable device in a wellbore comprises: introducing the flowable device into the wellbore, wherein the flowable device comprises: an orientor; and a body, wherein the body comprises a plurality of layers, wherein each of the layers comprises one or more materials, and wherein after introduction, the orientor causes the flowable device to be oriented in a preselected orientation within the wellbore.

According to yet another embodiment, a method of orienting a flowable device in a wellbore comprises: introducing the flowable device into the wellbore, wherein the flowable device comprises: a body; an orientor; and a communication device, wherein the communication device is operatively coupled to a transmitter and a receiver, wherein the orientor causes the flowable device to be oriented in a preselected orientation within the wellbore, and when the flowable device is in the preselected orientation, a more efficient coupling exists between the transmitter and the receiver via the communication device compared to a similar flowable device without the orientor.

Any discussion of the embodiments regarding the flowable device or any component related to the flowable device (e.g., the orientor) is intended to apply to all of the apparatus and method embodiments. Any discussion of a particular component of an embodiment (e.g., an orientor) is meant to include the singular form of the component and the plural form of the component, without the need to continually refer to the component in both the singular and plural form throughout. For example, if a discussion involves “the orientor,” it is to be understood that the discussion pertains to an orientor (singular) and two or more orientors (plural).

Referring now to the figures, FIG. 1 depicts a well system 10. The well system 10 can include at least one wellbore 11. The wellbore 11 can penetrate a subterranean formation 20. The subterranean formation 20 can be a portion of a reservoir or adjacent to a reservoir. The wellbore 11 can include a casing 12. The wellbore 11 can include only a generally vertical wellbore section or can include only a generally horizontal wellbore section. A first section of tubing string 15 can be installed in the wellbore 11. A second section of tubing string 16 (as well as multiple other sections of tubing string, not shown) can be installed in the wellbore 11. The well system 10 can comprise at least a first zone 13 and a second zone 14. The well system 10 can also include more than two zones, for example, the well system 10 can further include a third zone, a fourth zone, and so on. The well system 10 can further include one or more packers 18. The packers 18 can be used to isolate each zone of the wellbore 11. The packers 18 can be used to prevent fluid flow between one or more zones (e.g., between the first zone 13 and the second zone 14) via an annulus 19. The tubing string 15/16 can also include one or more ports 17. One or more ports 17 can be located in each section of the tubing string. Moreover, not every section of the tubing string needs to include one or more ports 17. For example, the first section of tubing string 15 can include one or more ports 17, while the second section of tubing string 16 does not contain a port. In this manner, fluid flow into the annulus 19 for a particular section can be selected based on the specific oil or gas operation.

It should be noted that the well system 10 is illustrated in the drawings and is described herein as merely one example of a wide variety of well systems in which the principles of this disclosure can be utilized. It should be clearly understood that the principles of this disclosure are not limited to any of the details of the well system 10, or components thereof, depicted in the drawings or described herein. Furthermore, the well system 10 can include other wellbore components not depicted in the drawing. For example, the well system 10 can further include a well screen. By way of another example, cement may be used instead of packers 18 to aid the isolation device in providing zonal isolation. Cement may also be used in addition to packers 18.

In an embodiment, a flowable device is introduced in the wellbore 11. The flowable device can be a rotationally symmetric bluff body (e.g., a spheroid). As used herein, the term “spheroid” means a body whose shape is substantially a ball, an oblate sphere, a sphere, a disc, corpuscular-shaped bodies, and any other similar shape. The largest or maximum dimension of the flowable device can be less than the inner diameter (I.D.) of the wellbore component in which the flowable device is introduced. For example, the wellbore component can be the wall of the wellbore or a tubing string located within the wellbore. According to an embodiment, the flowable device is an isolation device. The isolation device can be capable of restricting or preventing fluid flow between a first zone 13 and a second zone 14. The first zone 13 can be located upstream or downstream of the second zone 14. In this manner, depending on the oil or gas operation, fluid is restricted or prevented from flowing downstream or upstream into the second zone 14. As can be seen in FIG. 1, the first section of tubing string 15 can be located within the first zone 13 and the second section of tubing string 16 can be located within the second zone 14.

The isolation device can be a ball 30 (e.g., a first ball 31 or a second ball 32) and a seat 35 (e.g., a first seat 36 a or a second seat 36 b). The ball 30 can engage the seat 35. The seat 35 can be located on the inside of a tubing string. When the first section of tubing string 15 is located downstream of the second section of tubing string 16, then the I.D. of the first section of tubing string 15 can be less than the I.D. of the second section of tubing string 16. The I.D. of the second seat can also be larger than the I.D. of the first seat. This may be useful when the I.D. of the sections of tubing string is the same. In this manner, a first ball 31 can be placed into the first section of tubing string 15. The first ball 31 can have a smaller diameter than a second ball 32. The first ball 31 can engage a first seat 36 a. Fluid can now be temporarily restricted or prevented from flowing into any zones located downstream of the first zone 13. In the event it is desirable to temporarily restrict or prevent fluid flow into any zones located downstream of the second zone 14, the second ball 32 can be placed into second section of tubing string 16 and will be prevented from falling into the first section of tubing string 15 via the second seat 36 b or because the second ball 32 has a larger outer diameter (O.D.) than the I.D. of the first section of tubing string 15. The second ball 32 can engage the second seat 36 b. The ball (whether it be a first ball 31 or a second ball 32) can engage a sliding sleeve (not shown) during placement. This engagement with the sliding sleeve can cause the sliding sleeve to move; thus, opening a port 17 located adjacent to the seat. The port 17 can also be opened via a variety of other mechanisms instead of a ball. The use of other mechanisms may be advantageous when the isolation device is not a ball. After placement of the isolation device, fluid can be flowed from, or into, the subterranean formation 20 via one or more opened ports 17 located within a particular zone. As such, a fluid can be produced from the subterranean formation 20 or injected into the formation. The ball 30 can be pumped or dropped into the wellbore where it lands on its associated seat 35. The pressure in the wellbore zone below the ball 30 may be lower than the pressure in the wellbore zone above the ball 30.

The flowable device 30 comprises a body. The body can be solid. According to an embodiment, the body comprises a plurality of layers. Each layer can be circular in shape. The centers of the circular layers may be located on a line that is perpendicular to the planes of the circular layers. Each layer can be made of one or more materials. The materials can be the same or different. The layers can be nuggets of material bonded together. The layers can also be compressed layers of the materials. The material can be selected from the group consisting of a metal, metal alloy, thermoplastic, a composite material, and combinations thereof. The metal or the metal of the metal alloy can be selected from the group consisting of, lithium, sodium, potassium, rubidium, cesium, francium, beryllium, magnesium, calcium, strontium, barium, radium, aluminum, gallium, indium, tin, thallium, lead, bismuth, scandium, titanium, vanadium, chromium, manganese, iron, cobalt, nickel, copper, zinc, yttrium, zirconium, niobium, molybdenum, technetium, ruthenium, rhodium, palladium, silver, cadmium, lanthanum, hafnium, tantalum, tungsten, rhenium, osmium, iridium, platinum, gold, graphite, and combinations thereof. Preferably, the metal or the metal of the metal alloy is selected from the group consisting of iron, aluminum, stainless steel, nickel, copper, zinc, and combinations thereof. According to an embodiment, the metal is neither radioactive, unstable, nor theoretical. A composite material is made of two or more constituent materials, which can be chemically and physically different in characteristics. Unlike an alloy, it is not necessary for any of the constituent materials of a composite material to be a metal.

According to an embodiment as shown in FIG. 2A, after the flowable device 30 is introduced in the wellbore 11, it can travel through the wellbore 11 and the orientor causes the flowable device to land on an associated seat 35 in the wellbore 11 in a preselected orientation. The preselected orientation can be different based on a variety of factors, including the material the flowable device is made from. According to an embodiment, at least one or more of the plurality of layers lies in a plane that is substantially parallel to an axis that extends longitudinally through the wellbore 11 when the flowable device is in the preselected orientation. According to another embodiment, at least one or more of the plurality of layers lies in a plane that is substantially perpendicular to an axis that extends longitudinally through the wellbore 11 when the flowable device is in the preselected orientation.

After introduction into the wellbore, high pressure is typically exerted on one side of the flowable device 30. This can create large contact stresses between the flowable device 30 and the seat 35. The pressure differential causes a very high stress on the flowable device 30. Finite Element Analysis (FEA) of Von Mises stress shows that the stress is highly localized at the contact surface between the seat 35 and the flowable device 30, as seen in FIG. 2C. Von Mises is a theoretical measure of stress used to estimate yield failure criteria. In accordance with another embodiment, since the orientation of the flowable device 30 can be preselected, the flowable device 30 can be locally strengthened (for example, at the contact surface), which could then reduce the overall cost of the flowable device 30. Local strengthening may involve the addition of: a plate, namely, a metal plate or a ceramic plate, exotic or different composites, orienting the fibers in the composite in a manner such that the locally strengthened area is able to better support tensile forces and minimize ball failure. The area/portions of the flowable device 30 that are not locally strengthened can be manufactured from lower cost/weaker grade materials, which may reduce the overall cost of manufacturing the flowable device 30. The flowable device 30 can be strengthened by +/−10 degrees in an anticipated contact area. Local strengthening can obviate the addition of a metallic layer around the entire flowable device 30 and can, consequently, make the flowable device 30 less dense and easier to flow back with the produced fluids when compared to a similar device made substantially fully of a metallic material.

According to an embodiment, the portion of the flowable device 30 that contacts the seat 35 could be shaped to minimize any tensile forces in the flowable device 30. As an example, the flowable isolation device 30 could have a non-spherical shape. For example, at least a portion of the device could have a concave surface. For instance, while flowable devices 30 can fail due to shear, an embodiment similar to the one depicted in FIG. 3, where at least a portion of the device has a concave surface (that is, a substantially cap-shaped device), would be under compressive stress. This can allow the selection of metals that possess higher compressive strengths (sometimes twice as high) as their shear strengths. This can also enable the development of advanced flowable devices that are dissolvable, have neutral buoyancy, can withstand extreme pressures, and have other advantageous characteristics.

Turning now to FIG. 4, the flowable device 30 can have one or more orientors. According to an embodiment, the orientor is a source of magnetomotive force (MMF). For example, the orientor can be one or more permanent magnets, electromagnets, or a combination thereof. As is well known, a magnet is any material or object that produces a magnetic field. The magnetic field is responsible for creating a force that pulls on other ferromagnetic materials and attracts or repels other magnets. A permanent magnet is an object made from a material that is magnetized and creates its own persistent magnetic field. Materials that can be magnetized and which are strongly attracted to a magnet, are called ferromagnetic.

In accordance with an embodiment, the principles of ferromagnetism are applied to self-orient the flowable device 30 in the preselected orientation after introduction into the wellbore 11. Ferromagnetism is the basic mechanism by which certain materials form permanent magnets or are attracted to magnets. Ferromagnetic materials can include iron, nickel, cobalt and most of their alloys, some compounds of rare earth metals, and a few naturally-occurring minerals such as lodestone. Ferromagnetic materials, such as iron, are strongly attracted to both poles of a magnet. The atoms of ferromagnetic materials tend to have their own magnetic field created by the electrons that orbit them. Small groups of atoms tend to orient themselves in the same direction. Each of these groups is called a magnetic domain. Each domain has its own north pole and south pole. When a piece of iron is not magnetized, the domains will not be pointing in the same direction, but will be pointing in random directions canceling each other out and preventing the iron from having a north or south pole or being a magnet. When a magnetic field is introduced, the domains will start to line up with the external magnetic field. The more the magnetic field that is applied, the higher the number of aligned domains. As the external magnetic field becomes stronger, more and more of the domains will line up with it. Thus, there will reach a point where all of the domains within the iron are aligned/oriented with the external magnetic field, irrespective of how much stronger the magnetic field is made.

As shown in FIG. 4, two permanent bar magnets 41 a and 41 b can be located within the flowable device 30. The magnets 41 a and 41 b can be made of any ferromagnetic material. The magnetic flux lines go through the tubing string 45. The tubing string 45 may be magnetic. As depicted, the flowable device 30 is viewed along an axis of the tubing string 45. That is, the tubing string 45 is perpendicular to the plane of the page. As can be understood by a person of ordinary skill in the art, the magnets 41 a and 41 b will exert a force to try to minimize the reluctance of the flux path between their respective north and south poles. Therefore, the magnets 41 a and 41 b will orient the flowable device 30 (or will keep the flowable device 30 in a position) such that at least one of the magnets 41 a and 41 b lies in a plane that is substantially perpendicular to a longitudinal axis that extends through the wellbore. In other words, a portion of the magnetomotive force can be perpendicular to the longitudinal axis of the wellbore.

Other embodiments of the invention are depicted in FIGS. 5A-5C. In each of these embodiments, a plurality of magnets 41 a-41 f, etc. are configured such that they are capable of preferentially aligning the flowable device within the tubing string 45. For example, the magnets can be located off-center, down one axis, placed along an upper and lower periphery of the flowable device, etc., such that the flowable device 30 is optimally oriented in the preselected orientation in the wellbore 11. Although the various embodiments illustrated herein depict the use of two or more magnets in order to increase the strength of the magnetic field and facilitate stronger coupling between the flowable device 30 and tubing string 45, it should be understood that even a single magnet may be sufficient to orient the flowable device 30 in the preselected orientation. Depending on the number of magnets utilized and how they are placed inside the flowable device 30, the flowable device can be strengthened locally. If two magnets are used, the flowable device 30 can be locally strengthened, for example, at its top and bottom surface. As described earlier, local strengthening is a cost effective way to enhance the pressure differential rating and facilitates the reduction of the density of the flowable device compared to a solid metal device.

The following is one example of using magnets as the orientor. The flowable device 30 is introduced into the wellbore. During introduction into the wellbore, the flowable device 30 will travel in a preselected orientation due to the orientor. For example, the magnets 41 a, 41 b, etc. located inside the flowable device 30 would travel in a flat spin—that is, they would rotate around the axis of the tubing string 45 travelling down but would land in a flat position such that the plane in which the magnets 41 a, 41 b, etc. lie is perpendicular to the wellbore axis. Accordingly, the flowable device 30 can be capable of achieving a higher pressure differential rating when compared to a similar flowable device 30 without the orientor.

FIG. 6A depicts the orientor according to another embodiment. It should be understood that the preselected orientation of the flowable device is the same as the preceding discussion when the orientor is a magnet. According to this embodiment, the orientor comprises at least one flexible member 42. One end of the flexible member 42 can be attached to an external surface of the flowable device 30. The flexible member 42 can be a tail and may take on the appearance of a kite tail. The flexible member 42 can be leading or trailing the flowable device 30 after the device is introduced into the wellbore 11. In another embodiment, more than one flexible member 42, including, for example, a leading and trailing member can be attached to the flowable device 30. The flexible member 42 can have an adjustable stiffness. As can be appreciated, a stiffer flexible member 42 can lower the tendency of the flowable device 30 to change its orientation after it has been introduced into the wellbore. Therefore, once the flowable device, such as the ball 30, has been introduced in the wellbore 11 in the preselected orientation, the stiff flexible member 42 ensures that the flowable device 30 maintains the preselected orientation as it travels within the wellbore 11. Therefore, a worker at the surface of the wellbore 11 can ensure that the flowable device 30 is oriented in the preselected orientation based on the manner in which the flowable device 30 was introduced into the wellbore 11.

The flexible member 42 can be configured to be dissolvable. For example, the flexible member 42 can be made of a dissolvable material, such as polyglycolic acid “PGA”, aluminum, sugar, salts, sand, etc. such that it can be dissolved in the wellbore fluids. In another embodiment, the flexible member comprises rubber or thermoplastic materials that could dissolve or be heated to melt or dissolve at formation temperatures. In yet another embodiment, the flexible member 42 may be a eutectic system. In another embodiment, the flexible member 42 can comprise a memory-shaped alloy.

In an embodiment, the flexible member can 42 function as an antenna. For example, the antenna could be curled up when it is introduced into the wellbore 11. As it travels in the wellbore 11, the antenna is exposed to high downhole temperatures causing it to unfurl slowly. This further facilitates the orientation of the flowable device 30 in a desired manner.

In another embodiment, referring to FIG. 6B, a drag element 43 is affixed to an end of flexible member 42. The drag element 43 may be affixed to an end of flexible member 42 that is distal to the end that is attached to the flowable device 30. The drag element 43 comprises a weighted element configured to exert an additional drag on the flowable device 30. The weight of the weighted element can be adjusted depending on the density of the flowable device 30 and on the drag that is required to be exerted. The drag element 43 ensures that the flowable device 30 maintains the preselected orientation upon introduction and as it travels within the wellbore 11.

As can be seen in FIGS. 6A and 6B, the fluid in the wellbore (depicted by the arrow) can move around the flowable device 30 and can push the flowable device 30 downward. Thus, the flowable device 30 travels slower than the fluid. The flexible member/drag element 42/43 is carried further downstream than the flowable device 30 itself. Depending on how the flowable device 30 is used, for example, if the flowable device 30 is pumped in a hydraulic fracturing operation, then the flexible member/drag element 42/43 would be leading. But if ball is dropped in, such as while setting a packer, the flexible member/drag element 42/43 would trail the flowable device 30 since the fluid is already in the wellbore (as opposed to the fluid pumping the flowable device 30 down during hydraulic fracturing). The flexible member and drag element 42/43 are configured to orient the flowable device 30 in the wellbore 11, such that the flexible member is generally parallel to a longitudinal axis of the wellbore.

In yet another embodiment, the flowable device 30 comprises a body, an orientor, and a communication device (not shown). The communication device relays information from a transmitter to a receiver. The communication device can be an antenna. The body of the flowable device can include a transmitter and/or a receiver. According to this embodiment, the communication device can be operatively coupled to the transmitter and/or the receiver. Also according to this embodiment, a second transmitter and/or receiver can be located in the well system. Information can be relayed to the communication device located on or inside the flowable device via the second transmitter and/or receiver. When the flowable device 30 is introduced into the wellbore 11, the orientor (for example, the magnets/flexible member/drag element, described earlier) causes the flowable device 30 to orient itself in the preselected orientation as the flowable device travels within the wellbore 11. In this manner, once the flowable device is oriented within the wellbore, the communication device can be maintained in the preselected orientation. In the preselected orientation, a more efficient relay can exist between the transmitter and the receiver compared to a similar device without the orientor. Because the orientation of the flowable device 30 can be predicted, the communication device can be optimally positioned on or located within the flowable device 30. Thus, the communication device can provide a more effective communication network within the wellbore 11 where it can transmit and/or receive signals from other flowable devices and/or wellbore tools inside the wellbore 11 or at the surface of the wellbore 11.

Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is, therefore, evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention. While devices and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the devices and methods also can “consist essentially of” or “consist of” the various components and steps. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an”, as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted. 

What is claimed is:
 1. A method of orienting a flowable device in a wellbore comprising: introducing the flowable device into the wellbore, wherein the flowable device comprises: a body; and an orientor, wherein the orientor causes the flowable device to be oriented within the wellbore such that the flowable device has a higher pressure differential rating than a similar flowable device without the orientor.
 2. The method according to claim 1, wherein the flowable device has a maximum dimension that is less than the inner diameter of a wellbore component in which the flowable device is introduced.
 3. The method according to claim 1, wherein the flowable device is an isolation device.
 4. The method according to claim 3, wherein the isolation device is capable of restricting or preventing fluid flow between a first zone and a second zone of the wellbore.
 5. The method according to claim 3, wherein isolation device comprises a ball and seat.
 6. The method according to claim 3, wherein at least a portion of the isolation device has a concave surface.
 7. The method according to claim 1, wherein the orientor orients the flowable device in a preselected orientation after the step of introducing.
 8. The method according to claim 1, wherein the step of introducing comprises placing the flowable device in a desired zone of the wellbore.
 9. The method according to claim 1, wherein the orientor comprises a source of magnetomotive force.
 10. The method according to claim 9, wherein the source of the magnetomotive force is placed within the flowable device.
 11. The method according to claim 9, wherein the source of the magnetomotive force comprises at least one magnet.
 12. The method according to claim 9, wherein the source of the magnetomotive force comprises two or more magnets.
 13. The method according to claim 11, wherein at least a portion of the magnetomotive force lies in a plane that is substantially perpendicular to a longitudinal axis that extends through the wellbore.
 14. The method according to claim 1, wherein the orientor comprises at least one flexible member.
 15. The method according to claim 14, wherein one end of the at least one flexible member is attached to an external surface of the flowable device.
 16. The method according to claim 14, wherein the at least one flexible member comprises a tail.
 17. The method according to claim 14, wherein the at least one flexible member has an adjustable stiffness.
 18. The method according to claim 15, wherein the at least one flexible member further comprises a drag element, and wherein the drag element is affixed to an end that is distal to the end attached to the external surface of the flowable device.
 19. The method according to claim 18, wherein the flexible member and drag element are configured to orient the flowable device in the wellbore in a preselected orientation.
 20. A method of orienting a flowable device in a wellbore comprising: introducing the flowable device into the wellbore, wherein the flowable device comprises: an orientor; and a body, wherein the body comprises a plurality of layers, wherein each of the layers comprises one or more materials, and wherein after introduction, the orientor causes the flowable device to be oriented in a preselected orientation within the wellbore.
 21. The method according to claim 20, wherein at least one or more of the plurality of layers lies in a plane that is substantially perpendicular to an axis that extends longitudinally through the wellbore when the flowable device is in the preselected orientation.
 22. The method according to claim 20, wherein at least one or more of the plurality of layers lies in a plane that is substantially parallel to an axis that extends longitudinally through the wellbore when the flowable device is in the preselected orientation.
 23. The method according to claim 20, wherein the flowable device is a spheroid.
 24. The method according to claim 20, wherein after the flowable device is oriented in the preselected orientation within the wellbore, the flowable device has a higher pressure differential rating than a similar flowable device without the orientor.
 25. A method of orienting a flowable device in a wellbore comprising: introducing the flowable device into the wellbore, wherein the flowable device comprises: a body; an orientor; and a communication device, wherein the communication device relays information from a transmitter to a receiver, wherein the orientor causes the flowable device to be oriented in a preselected orientation within the wellbore, and when the flowable device is in the preselected orientation, a more efficient relay exists between the transmitter and the receiver via the communication device compared to a similar flowable device without the orientor.
 26. The method according to claim 25, wherein the communication device is an antenna.
 27. A wellbore flowable device comprising: an orientor, wherein the orientor causes the flowable device to be oriented within the wellbore such that the flowable device has a higher pressure differential rating that a similar flowable device without the orientor. 